The market price for ethane is well below historical values, and projections indicate that this condition will persist. What are the options to find economical applications for gas and related hydrocarbons?

The abundance of natural gas in widespread US locations has
resulted in many resources being classified as remote or
stranded. It is creating the need for economical options to
move these resources to market. In many cases, the gas is
ethane-rich, and there is a need for new ways to monetize a
low-value ethane product. The present market price for ethane
is well below historical values, and projections indicate that this
market condition will persist. What are the options to find
economical applications for natural gas and related
hydrocarbons?

Abundant natural gas supplies

US natural gas production has increased substantially over
the past 10 years. Fig. 1 shows the level of
increased natural gas production for US and individual states.
The greatest sources for new natural gas supplies have been
through the exploitation of shale formations. These increases
have been seen not only in traditional gas production areas
such as Texas and Louisiana, but also in nontraditional places
such as Pennsylvania and Arkansas.

Fig.
1. US natural gas
production.1

In many areas, large quantities of natural gas are being
flared due to the lack of pipeline availability and
infrastructure. For example, as of June 2012, in North Dakota,
over 200 MMscfd of natural was flared. This represents about
one third of the total gas production in the state.2
Some of these wells will be connected to a pipeline within a
year, while others will continue to be flared on a longer-term
basis. Along with the large increase in natural gas production
in the US (Fig. 1), there has been an even
larger increase in natural gas liquids (NGLs), of which ethane
is the greatest volume, as shown in Fig.
2.3

Fig.
2. US ethane production.3

From 1984 to 2008, ethane production gradually rose by
approximately 40%, from 500,000 bpd (500 Mbpd) to 700 Mbpd.
From 2008 to 2012, ethane production grew almost another 40%,
from 700 Mbpd to nearly 1 million bpd. These production numbers
do not include the more than 50 Mbpd that was either flared or
rejected into the residue gas stream. In total, the US has
increased available ethane more in the last four years than in
the previous 24 years collectively.

Value of ethane

By far, the dominant use of ethane is as a feedstock to US Gulf Coast steam
crackers for ethylene production.4 However, ethylene
is not a finished product; it is not easily transported outside
of the limited ethylene pipeline networks along the Gulf Coast.
The only other significant use for ethane is fuel value, which
sets the floor price.4

Due to ethanes limited value in total hydrocarbon production, shale plays are
frequently developed without significant thought to disposition
of the ethane as a stand-alone product.2 For
example, in a typical Bakken gas with 12.2 gpm, the ethane
content can represent about 44% of the total NGLs by volume,
but only 14% of the value. If the gas is produced in
association with oil from a well with a gas-to-oil ratio of 1.1
MMscf/bbl, the ethane represents a meager 1% of the value of
the hydrocarbons, despite being 10% of the total hydrocarbon
liquids produced.

The prices for Henry Hub natural gas, Mont Belvieu purity
ethane, and West Texas Intermediate (WTI) crude, all in terms
of $/MMBtu, are shown in Fig.
3.57 Historically, ethane has tracked
near WTI, based on respective heating values. This was true
until 2008, when ethanes value decreased relative to
crude oil. The primary reason for this drop was that newly
available ethane began flowing, much of it from Texas shale.
From Fig. 3, the market separation in terms of
$/MM-Btu between gas and ethane prices and crude prices is the
highest over the last seven years at least. Furthermore, this
trend is expected to continue for many years.

Fig.
3. Historic oil, residue, gas and ethane
prices.57

Fig. 4 shows the ethane production for the US
and the Texas Inland refinery district, which includes
the Eagle Ford, Barnett and Permian basins.8 From
this figure, the estimated ethane production for the Appalachia
1 and Minnesota, Wisconsin, North Dakota, South Dakota
(Midwest) refinery districts, which include
the Marcellus/Utica and Bakken, respectively, is presented.
While the Marcellus/Utica and Bakken districts had no
significant ethane production reported, the figure shows the
estimated ethane amounts produced from the fields and sold with
the residue gas, based on other NGLs produced.

Fig.
4. US ethane production.8

From 2008 to 2011, ethane maintained a significant cost
premium over natural gas, despite the rising supply, as shown
in Fig. 3. With the increasing price
separation between oil and ethane, ethylene crackers that used
heavier, oil price-dependent feeds such as naphtha, butane and
propane began shifting their feedstock to cheaper
ethane.4, 9

Limits on ethane price/demand growth

Several new ethylene plants and expansions of existing facilities have been announced. The
new capacity will consume some of the expected ethane
production.4 To integrate these plants with existing
infrastructure for feedstock delivery and product off-take,
they are almost exclusively built on the US Gulf
Coast.4 This proximity to other ethylene producers
requires world-class economies of scale to compete. As such,
these olefin plants represent very large ethane commitments,
typically on the order of 95 Mbpd (149 MMscfd) of ethane for
the service life of the plant. They also involve very large
capital commitments, in the range of $1.7 billion (B) to $3 B
depending on the sophistication and product slate.10,
11 Because recent shale resources are located far from
the Gulf Coast, extensive pipelines are required to bring the
ethane to the olefin crackers. The risks of constructing new
ethylene capacity, including feedstock, transportation,
competition and capital are sizeable, on top of the normal risk
of price and demand for the final product.

Transporting ethane from new production areas, such as the
Bakken and Marcellus fields, is not a trivial matter. Even if a
pipeline exists and capacity is available, transportation costs
impact ethane value to the producer significantly. The
estimated transportation fees associated with moving ethane
from some of the major shale basins to Mont Belvieu are shown
in Table 1. In most instances, a purity ethane
pipeline was not available, so pricing for a Y-grade product is
used in this table.

The opportunity

The problem of residue gas and ethane oversupply and,
particularly, localized oversupply in stranded locations is
finding a solution to convert moderate quantities (15 MMscfd to
50 MMscfd) of residue gas and ethane to a higher-value and more
easily transported product. These small volumes are outside the
reasonable scale of a local ethylene plant. In many
cases, pipelines may be at capacity or not available at all.
Furthermore, even if pipeline capacity is available, high
transportation fees may result in very low prices for natural
gas and ethane in the field. In addition, the present trend of
very large differences in gas and ethane prices relative to
crude prices is expected to continue.

New process

To cover this engineering gap, a new technology has developed to convert
natural gas and light hydrocarbons into a high-value, easily
transportable gasoline product, thus substantially increasing
the value of the end product.* The small plant size
allows installing units at the production sites. In addition, a
pipeline is not necessary, as the product can be easily
transported by truck or rail.

The innovative process is an integrated conversion process
to transform light hydrocarbons into a gasoline product, as
shown in Fig. 5. The cracking reactor, or
thermal cracker, operates by combusting fuel gas with oxygen to
generate a very high-temperature flame. The feed hydrocarbon is
preheated in a heat exchanger and then injected into the stream
of combustion products to raise the temperature of the feed to
the cracking temperature. The cracking of the feed takes place
almost instantly. The yield to ethylene and acetylene ranges
between 40%80%, depending on feed composition. The
reaction is water quenched to inhibit byproduct reactions that
generate carbon monoxide and coke. Due to the nature of thermal
reactions, some coke is produced. At these conditions, coking
is typically 2%3% of the inlet carbon. The largest size cracking
reactor available is suitable for approximately 5 MMscfd of
natural gas feed. For a commercial plant, the appropriate
number of thermal reactors would be operated in parallel.

Fig.
5. Process flow diagram.

The cracked gas is further cooled by cross-exchange to recover
heat and sent to the spray tower. Here, the cracked gas is
washed with circulating water to further cool the gas, to
condense the combustion water and to remove any coke particles.
Once the cracked gas has been cleaned and cooled, it is
compressed to approximately 150 psig with a multi-stage rotary
screw compressor. The cracked gas then flows to the ethylene
reactor where the acetylene is converted to ethylene.

The ethylene-rich product from the ethylene reactor is then
preheated and fed to the product reactor to yield gasoline
blendstock. The product blendstock consists primarily of
C6C8 with some lighter components
down to C4 and some heavier components up to
C11. The product contains about 30 wt% aromatics,
usually toluene and xylene, as well as a small quantity of
naphthenes (5 wt%10 wt%). The remainder is a mixture of
mostly branched paraffins. Olefins are typically less than 3
wt%. The gravity falls in the range of
50°API60°API with a research octane number of
9395. A refrigerated lean-oil absorption system is used
to efficiently recover the product from the gas stream. A
product stabilizer may be used to yield a gasoline blendstock
to meet a particular Reid vapor pressure.

The residue gas can be used as fuel. To reduce the buildup
of inerts within the recycle loop, an amine sweetening
unit removes the carbon dioxide from the fuel gas returning to
the burner. The remaining fuel is available for heating or
power production.

Process economics

Based on current market conditions, two options for
processing remote and stranded natural gas and ethane are
presented. The first option reviewed is for 20 MMscfd of
stranded or remote natural gas of approximately 1,250 Btu/scf
gross heating value. For natural gas with limited possibilities
for a pipeline or gas that is being flared, the producer should
consider all available alternatives to create additional
revenue. The new process produces approximately 1,710 bpd of
liquid product with estimated annual gross revenue of $60 MM.
As expected, the net revenue from the process is directly tied
to the cost of the natural gas feedstock price. As shown in
Table 2, the estimated payout for natural gas
ranges from 2.8 years for $0/MMBtu gas to 4.3 years for
$2/MMBtu gas. Gas feeds with heating values higher than 1,250
Btu/scf would produce larger amounts of liquids and would have
corresponding shorter payout times.

The second option reviewed is for 20 MMscfd ethane feed of
approximately 1,770 Btu/scf gross heating value. The new
approach converts this potentially low-value gas stream into a
saleable liquid product of approximately 3,660 bpd.*
In economic terms, the $4/MMBtu or less feed stream is now
worth $16/MMBtu as a liquid product based on present market
prices, as shown in Fig. 3. In addition, with
payout times less than three years, the process is very
attractive in terms of capital investment and future profits.
Upon payout, the process continues to yield substantial profits
even if ethane prices increase. HP

ACKNOWLEDGMENT

This is a revised and upgraded version of a previous
presentation from the 21st Gas Processors Associations
Annual Meeting, April 89, 2013, San Antonio, Texas.

NOTES

* Synfuels International Inc. has developed a new
process, Synfuels GTL; it is an integrated conversion process
to transform light hydrocarbons into a gasoline product.

The authorsJerry Bullin is a graduate of the
University of Houston with BS, M.S and PhD degrees in
chemical engineering. He is a registered Professional
Engineer in the state of Texas, and has worked for
several years as a process engineer. In addition, Dr.
Bullin was a professor in the Chemical Engineering
Department at Texas A&M University for 25 years. At
present, he is president of Bryan Research &
Engineering, Inc., a firm that develops and markets
process simulation software for the oil and gas, refining, and chemical
industries.Gavin McIntyre is manager of process
applications and customer service at Bryan Research
& Engineering, Inc. He has more than 19 years of
experience in process simulation and the oil and gas
industry. Mr. McIntyre holds a BS in chemical
engineering from Texas A&M University.

R. Clark Butts, PE, is president and
CEO of BCCK Engineering, Midland, Texas. In this role,
he directs all company operations, investments and projects in addition to
developing and implementing new technology. Mr. Butts holds
patents related to nitrogen rejection and has over 35
years of experience in the fields of natural gas
processing, treating and dehydration. His areas of
expertise include nitrogen rejection, carbon dioxide removal and
sequestration, helium extraction, oxygen removal and
NGL recovery. He developed the Nitech technology, which is used on
high nitrogen natural gas streams and is also being
successfully used in a broad range of
applications.

Bryon Cheatham currently serves as
vice presidentengineering at BCCK Engineering,
Inc. in Midland, Texas. He joined BCCK as process
engineer in 2000 after beginning his career in the refining industry where he
has also worked in upstream production and operations.
Mr. Cheatham holds a BS degree in chemical engineering
from the University of Texas.

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The para above Table-2 needs corrections as follows, to match with the calculation in Table-2 :

.... the estimated payout for natural gas ranges from 3.5 years (NOT 2.8 years) for $0/MMBtu gas to 5.4 years (NOT 4.3 years) for $2/MMBtu gas.

Athol Love03.03.2014

As a structural engineer asked to provide pump bases and inlet/outlet pipe supports I can say that few engineers understand this inter-relationship between equipment and its supports properly.

Kamogelo10.21.2013

There are a couple of fainciatsng points soon enough in the following paragraphs but I do not know if I see these people center to heart. There is some validity but I’m going to take hold opinion until I explore it further. Excellent write-up , thanks and that we want a lot more! Added to FeedBurner also

Mohamed EL ABD10.17.2013

reduction of gas flaring during oil and gas production and recover the associated gas to re-use this as fuel or sell it as feedstock.please help